6. ISO's Economic Analysis

The ISO conducted two studies estimating the economic impacts of Path 15 upgrades for a single year, 2005. The year 2005 was chosen because it was the first full year that the project was assumed fully operational. The first study, entitled "Path 15 Expansion Economic Benefit Study: Phase II--Year 2005 Prospect", presents an economic assessment of the value of the project assuming a competitive market.¹¹ The second study, entitled "Potential Economic Benefits to California Load From Expanding Path 15-Year 2005 Prospect", presents an economic assessment of the value of the project in the year 2005 as a risk mitigation measure to minimize the exercise of market power.¹²

In each of these studies, the ISO performed model runs to examine the impact of existing transmission contracts (ETCs) on project benefits. ETCs are existing transmission rights that predate ISO operations. Before describing the ISO study methods, input assumptions and results below, we first present a brief overview of how the ISO describes ETCs and their scheduling impact on Path 15 transmission capacity.

6.1 ETCs and the Problem of Phantom Congestion

There was extensive testimony and cross-examination in this proceeding on the problem of "phantom" or "paper" congestion caused by ETCs. ETCs are currently held by the California Department of Water Resources (CDWR), Transmission Agency of Northern California, Turlock Irrigation District, Los Angeles Department of Water and Power (LADWP) and Pacificorp. As of March 31, 2002, the maximum contract capacity under ETCs totaled 2022 MW.¹³

The ISO witnesses describe the problem of phantom congestion as follows: FERC has required the ISO to honor all ETCs.¹⁴ Many ETCs give their holders scheduling rights up to 20 minutes (or less) prior to transaction times:

"As a result, the transmission capacity associated with ETCs is unavailable to Market Participants until 20 minutes or less prior to transaction time. Since all other Market Participants must submit Hour-Ahead Schedules to the CA ISO two hours prior to the hour in which a transaction occurs, Market Participants cannot utilize any ETC capacity that may become available 20 minutes prior to the hour. While FERC has on several occasions asked questions about its policy of honoring ETCs, to date it has maintained the policy."¹⁵

ISO Witnesses Greenleaf and Casey explained during hearings in more detail how they view the impact of ETCs on day-ahead and hour-ahead scheduling on Path 15.¹⁶ Under ISO tariffs, this scheduling process begins with submittals by PG&E and Southern California Edison (SCE) for day-ahead total capacity reservations on Path 15 as well as specific schedules (hour-by-hour flows) for each ETC holder across Path 15. These day-ahead reservations and schedules must be made by 10:00 a.m. the day prior to the date of usage.¹⁷ The ISO then subtracts the total amount of ETC reserved capacity from the MWs of available transmission capacity that the ISO can offer to other market participants ("new firm users") for scheduling in the day-ahead market.

Even though the ETC schedules submitted by PG&E and SCE in the day-ahead market have historically added up to far less MWs than the amount of total capacity reserved, the ISO holds the full capacity reservations until at least the hour-ahead market.¹⁸ In that market (which closes two hours prior to the operating hour), ETC holders can further revise their day-ahead schedules up to the full capacity reservation amounts. In addition, most of the ETC holders have existing contract rights to schedule up to 20 minutes (or less) prior to the hour, and ISO Witness Casey testified that most of the ETC capacity reservations are actually held up to that time.¹⁹ As a result, in practice, the ISO withholds from the day-ahead and hour-ahead markets the full amount of ETC capacity reservations, regardless of what amounts are actually scheduled in those markets. Whatever capacity is not used by 20 minutes before the hour becomes available for dispatch in real time. By that time, however, other market participants have lost their ability to submit additional schedules.

As a result, once the day ahead reservations by ETC holders are locked in, the full amount of reserved capacity is lost to the system, even if it is ultimately not all used by the ETC holder. In this manner, the amount of ETC contract capacity that has been reserved in the day-ahead and hour-ahead markets, but not ultimately used, creates "phantom" or "paper" congestion.

In the studies discussed below, the ISO assumed that ETC holders in 2005 will reserve the same amount of capacity on Path 15 that ETC holders reserved in 2000.²⁰ Under the "exclude ETC" scenarios, the ISO assumes that none of the unused reserved capacity in the day-ahead or hour-ahead markets would be released, i.e., that all of it would remain unavailable to other transmission users, even if it were not utilized by ETC holders. Under the "include ETC" scenarios, the ISO assumes that all of the unused reservation capacity would be released so that other users could schedule that capacity.

6.2 Path 15 Economic Assessment Assuming
Competitive Market

For this study, the ISO modeled the economic dispatch of a cost-based, transmission constrained system, similar to the methods used by the ISO in its congestion management activities. The ISO obtained the majority of the model input assumptions from the California Energy Commission (CEC), including loads, imports, fuel prices, unit operating characteristics and plant retirements.

The ISO refers to zones NP15, ZP26 and SP15 in its various scenarios: NP15 as being the zone north of Path 15; ZP26 and SP15 as being the zones south of Path 15. Since Path 15 connects ZP26/SP15 to NP15, the flow on this path is impacted by the amounts of new generation on either side.

The key assumption of this study is that market power is not being exercised. No single supplier has the ability to manipulate prices and each supplier bids its actual marginal costs. Under this assumption, the model simulates cost-based bidding based on incremental heat rates, forecasted fuel prices (for the gas-fired generators) and variable operation and maintenance costs. During hours of congestion over Path 15, market clearing prices will reflect the higher costs of less efficient resources that need to be dispatched from alternate locations. By reducing congestion on Path 15, the project allows for a more efficient dispatch of generation resources, thereby lowering the market clearing price and producing project benefits.

The ISO used a load forecast based on year 2000 actual load with the CEC providing load growth factors through 2005. Three scenarios were used for new internal generation:

· A NP15 low scenario, in which a lower percentage of generation is built in NP15 and more in ZP26/SP15. For NP15, this includes the 4300 MWs projects already approved by the CEC plus 291 MW of peaker capacity.

· A medium or average scenario, where the same percentages of total capacity in NP15 and ZP26/SP15 are assumed to be built. For NP15, this includes 4300 MWs of projects approved by the CEC, 2800 MWs of projects pending approval, plus 291 MW of peaker capacity.

· A NP15 high scenario in which a larger percentage is built in NP15 as compared to ZP26/SP15. For NP15, this includes the new generation projects assumed in the medium scenario plus another 2,382 MWs of "announced" new projects (press release only).

The ISO also assumed that new generation external to the ISO control area in the northwest and southwest would also be built by 2005, and obtained data on projected new generation from the CEC. The ISO then applied the same proportions applied to new internal generation numbers to develop three new external generation scenarios: an average scenario, an NP15 low scenario and an NP 15 high scenario. For example, the NP15 low scenario assumes a low level of new capacity in NP15 and in the Pacific Northwest.

The ISO ran all each of the new generation scenarios assuming average hydro conditions (in 2000) and assuming one-in-ten year drought conditions (64 percent of 2000). In addition, the ISO performed three additional hydro sensitivities with the low NP15 generation cases. These sensitivity cases modeled three hydro conditions that fall between the average hydro year and the one-in-ten drought year assumptions. In addition, the ISO performed a sensitivity case on the low NP15/dry hydro scenario to examine the impact of retaining ("exclude") or releasing ("include") unused ETC capacity on project benefits.

For each hour and each different scenario, the ISO produced one simulation with the Path 15 rating unchanged (the status quo case) and one simulation with the rating at the value determined with the additional 500 kV line. The ISO calculated the difference between economic indicators under the status quo and new rating cases to determine the net economic benefits of the project. In particular, the ISO examined the differences in "energy cost to load" and "re-dispatch costs". Energy cost to load looks at changes in the market-clearing price due to reduced congestion on Path 15. Re-dispatch costs looks at the way plants are dispatched to meet load-i.e., where along their production supply curves they produce power. Changes in re-dispatch costs are relatively insignificant. The vast majority of benefits discussed below relate to changes in energy cost to load.

The results of the ISO's assessment are presented in Table 1. As indicated in that table, in four out of the ten scenarios, the annual benefits of the Path 15 upgrade in the year 2005 are negative by approximately $2.5 to $7.5 million, that is, the energy cost to load actually increases relative to the status quo. This is because the market prices in Zones ZP26/SP15 (south of Path 15) increase more than prices decrease in Zone NP15 (north of Path 15). As ISO Witness Casey explained:

"When you have upgrades to Path 15, the price in the north becomes lower because you are less dependent on the higher cost of units north. But because southern units are supplying generation to the north, the price in the south goes up. So, the cost impact to the north is their costs go down because they are facing a lower price. The cost impact in the south is their costs go up because they are facing a higher price. When you net those two, depending on the relative change in prices and the magnitude of load in the north and south, you can get a negative or a positive number."²¹

In all the scenarios where either (1) average hydro year conditions or (2) medium or high new generation north of Path 15 are assumed, the annual benefits of the line are less than the cost. In the scenarios that assume average hydro conditions, the project costs exceed benefits by $47 million/year or more, regardless of the level of new generation assumed.

Project benefits show positive values in 2005 only under the scenarios that assume a low NP15 generation scenario. However, they are still less than the projected annual costs of the project for all but two scenarios. For example, the scenario that modeled hydro conditions half way between an average year and approximately a one in ten year drought shows a benefit of only $14 million in terms of cost to load and a benefit of only $2.4 million in terms of re-dispatch costs.

Projected annual benefits in year 2005 are greater than the annualized cost of the project ($50 million) if one assumes one in ten year drought conditions and low NP15 generation development. The sensitivity case excluding all ETC capacity (i.e., assuming that none of the unused capacity is released) shows a further increase in benefits in 2005.

6.3 Path 15 Economic Assessment Assuming
Market Power

After completing the first study, the ISO filed a motion for extension of time in order to undertake an "assessment of market impacts that were not accounted for and reviewed in the initial work." ²² In this second study, the ISO examined the extent to which suppliers may be able to exercise market power in northern California (NP15) in the year 2005 under various new generation and hydro condition scenarios. The ISO utilized the same supply scenarios used in the study described above, but added scenarios relating to 1) the availability of transmission capacity subject to ETCs and 2) the State's long-term power contracts. The ISO then assessed the extent to which market power is mitigated through the addition of the Path 15 upgrades.

This assessment involved five steps. First, the ISO compared actual market prices in 2000 (from October 1999 to November 2000) with a forecast of what competitive prices should have been, using the competitive pricing model described above. This results in an estimate of the "price-cost markup" or "Lerner Index" in each hour, based on 2000 data. More specifically, the ISO calculated the percent by which actual prices were above estimated marginal costs in 2000.

Second, the ISO measured the ability of suppliers to exercise market power in 2000 by calculating the Residual Supply Index (RSI). The RSI is a measure of market concentration-more specifically, of whether the largest seller in a particular market is pivotal in the sense that total market demand could not be met absent that seller's supply. Mathematically, the RSI is the ratio of total supply minus the largest supplier, divided by total demand. An RSI value less than 100% would indicate that the largest supplier is pivotal and thus would have the ability to set the clearing price. As the ISO explained during hearings, it has data on the capacity of each individual supplier in the market. Using that information and data on actual demand and total supply during 2000, the ISO was able to calculate RSIs for each hour in 2000.²³

Third, the ISO conducted a regression analysis using this 2000 data. Specifically, the ISO regressed the Lerner Index (price-cost markup) against the RSI and actual system loads in each hour. This regression established a statistical relationship with which the ISO estimated price-cost mark-ups in each hour, given hourly values for RSI and loads.

Fourth, the ISO calculated RSIs for every hour in 2005 with and without the proposed expansion of Path 15. Using the statistical relationship described above, the ISO estimated the resulting price-cost markups in each hour to produce the costs due to market abuse with and without the Path 15 upgrades. The total economic benefits for year 2005 are the sum of the differences in these costs (with and without the Path 15 upgrades) for all hours in 2005.

The ISO conducted this analysis for a total of 24 different modeling scenarios. Twelve scenarios looked at two hydro conditions (dry, normal), three projections for new generation in NP15 (low, medium, high), and two conditions (100% and 0%) regarding the release of unused ETC capacity on Path 15.

The ISO then evaluated each of these 12 scenarios with and without the State's long-term power contracts. Prior to the DWR entering into long-term contracts in 2001, all power purchases for investor-owned utility ratepayers were obtained through a bidding process in the power exchange, or "spot" market. As ISO Witness Casey explained during evidentiary hearings, by entering into contracts (or "forward contracting"), rather than relying on the spot market, the State could mitigate the market abuses that were occurring:

"...the key mitigation elements of forward contracting are both that it reduces the amount of demand that is exposed to the shorter term market, which is more susceptible to market power, and...it reduces the suppliers' incentive to exercise market power in the shorter term markets."²⁴

"...if a supplier has committed a significant amount of its capacity to long-term contracts...the benefit of submitting high prices or withholding capacity, the benefit for exercising market power, is diminished."²⁵

Under the "with long-term contracts" scenario, the ISO subtracts from the total load the amount that is covered by the DWR's long-term contracts. Only the remaining load (also referred to as the "net-short position") is subject to the price-cost markups estimated through the RSI methodology. The "without long-term contracts" scenario assumes that DWR no longer holds the long-term power contracts it negotiated in 2001, and therefore all of the purchases in the market are subject to the price-cost markups estimated through the RSI methodology. As one would expect, the project benefits under the "without" scenarios are substantially higher than under the "with" scenario. This is because the price-cost markups will apply to a larger amount of load. Conversely, when market power is mitigated through other measures (e.g., long-term contracts), reducing congestion on Path 15 has less economic impact. The mitigation effects of long-term contracts are due to the fact that the load under the contract is removed from the spot market. Those effects are independent from the prices negotiated under the contract, and do not speak to the issue of whether or not those prices are reasonable.

The results are summarized in Table 2. A more detailed presentation of the study results is presented in Tables 3 and 4. In the scenarios assessed, the ISO estimates that the potential benefits to load in northern California (NP15) range from $12 million to $1.3 billion, depending upon the assumptions made about hydro conditions, the development of new generation, availability of transfer capability subject to ETCs, and whether the State continues to hold long-term power contracts in 2005. The benefits of the upgrade are highest under a combination of one or more of the following assumptions for the year 2005: (1) no unused ETC capacity is released ("exclude ETC") (2) a low build-out of generation in NP15 ("low new generation"), (3) the State no longer holds long-term contracts with suppliers ("exclude long-term contract"), and/or (4) one-in-ten drought year conditions ("dry hydro").